In oil-well primary cementing, it is generally required that the pressure resulting from the hydrostatic head of the column of cement slurry and other wellbore contents not exceed the fracture pressure of the formation. If this pressure exceeds the formation fracture pressure, a fracture may form. Cement slurry flowing into the fracture then decreases the amount of cement within the borehole, and an inadequate amount of cement may remain in the borehole to support the casing. Casings are therefore cemented into wellbores in formations having a low fracture gradient using low density cement slurries.
Low density cement slurries can be provided by creating a foam from the slurry, diluting the cementitious components with additional water, or including in the slurry a low density aggregate such as graphite or hollow spheres. These low density cement slurries generally result in set cements having relatively low compressive strengths, high porosity and low thermal conductivity.
It is therefore sometimes advantageous to use higher density cement slurries and avoid fracturing the formation by other means. For example, a wellbore can be cemented in stages. In each stage, a portion of the wellbore is cemented. The portion is small enough that the static head of even a high density cement and other wellbore fluids do not exceed the fracture pressure of the formation. Staged cementing is time consuming and can result in discontinuities in the set cement.
High density cement slurries are preferred for cementing wellbores for recovery of hydrocarbons by thermal recovery processes. In particular, heat injection wells in thermal conduction process are preferably cemented with cements that can withstand high temperatures for extended periods of time, and have high thermal conductivity. High alumina content cements meet these requirements, and have low porosity and high strength. But high alumina content cement slurries are generally very dense.
Cement slurries typically contain fluid loss additives to reduce the loss of water from the slurry into permeable formations. This fluid loss can result in the slurry becoming dehydrated and viscous. This is called "flash setting" and is typically avoided in well cementing art by the use of ample initial water in the slurry and fluid loss additives. Polymers are often used as fluid loss additives used in cement slurries. Such polymers function by creating an immobile gel in pores of the formation adjacent to the cement slurry. Fluid loss additives therefore do not prevent or control fracturing but only prevent the loss of water from the slurry prior to hydration.
It is therefore an object of the present invention to provide a method to cement a wellbore wherein the cement slurry density exceeds the fracture gradient of the formation in which the cement is to be placed.